Ethoxylated amines for use in subterranean formations

ABSTRACT

Methods for treating subterranean formations are provided. In one embodiment, the methods comprise providing a treatment fluid comprising an aqueous base fluid and a surfactant comprising an ethoxylated amine or derivative thereof; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation; and producing fluids from the wellbore during or subsequent to introducing the treatment fluid into the wellbore.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is a U.S. National Stage Application ofInternational Application No. PCT/US2015/060924 filed Nov. 16, 2015,which is incorporated herein by reference in its entirety for allpurposes.

BACKGROUND

The present disclosure relates to methods for treating subterraneanformations, and more specifically, methods for treating subterraneanformations with treatment fluids comprising surfactants.

Hydrocarbons, such as oil and gas, are commonly obtained fromsubterranean formations that may be located onshore or offshore. Thedevelopment of subterranean operations and the processes involved inremoving hydrocarbons from a subterranean formation typically involve anumber of different steps such as, for example, drilling a wellbore at adesired well site, treating the wellbore to optimize production ofhydrocarbons, and performing the necessary steps to produce and processthe hydrocarbons from the subterranean formation.

Surfactants are widely used in treatment fluids for drilling operationsand other well treatment operations, including hydraulic fracturing andacidizing (both fracture acidizing and matrix acidizing) treatments.Surfactants may also be used in enhanced or improved oil recoveryoperations. Many variables may affect the selection of a surfactant foruse in such treatments and operations, such as interfacial surfacetension, wettability, compatibility with other additives (such as otheradditives used in acidizing treatments), and emulsification tendency.Surfactants are an important component in treatment fluids for ensuringhigher productivity from unconventional oil and gas formations.Surfactants may provide more effective fluid loss control, fluidflowback efficiency, and oil recovery. For example, surfactants mayimprove oil recovery by reducing interfacial tension, altering thewettability of the subterranean formation, and/or stabilizing anemulsion. However, conventional surfactants may present environmental,health, and safety concerns. In addition, conventional surfactants maybe sensitive to changes in pH, temperature, and salinity.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating an example of a fracturing system thatmay be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a diagram illustrating an example of a subterranean formationin which a fracturing operation may be performed in accordance withcertain embodiments of the present disclosure.

FIGS. 3A and 3B are graphs illustrating data relating to thermalstability of an ethoxylated amine formulation of the present disclosureand a field standard non-emulsifying surfactant formulation.

FIG. 4 is a graph illustrating data relating to pH and salinitystability of an ethoxylated amine formulation.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

Illustrative embodiments of the present disclosure are described indetail herein. In the interest of clarity, not all features of an actualimplementation may be described in this specification. It will of coursebe appreciated that in the development of any such actual embodiment,numerous implementation specific decisions may be made to achieve thespecific implementation goals, which may vary from one implementation toanother. Moreover, it will be appreciated that such a development effortmight be complex and time consuming, but would nevertheless be a routineundertaking for those of ordinary skill in the art having the benefit ofthe present disclosure.

The present disclosure relates to methods for treating subterraneanformations. Particularly, the present disclosure relates to methods forthe use of ethoxylated amines in subterranean formations.

More specifically, the present disclosure provides methods thatcomprise: providing a treatment fluid comprising: an aqueous base fluid,and a surfactant comprising an ethoxylated amine or derivative thereof;introducing the treatment fluid into a wellbore penetrating at least aportion of a subterranean formation; and producing fluids from thewellbore during or subsequent to introducing the treatment fluid intothe wellbore. In certain embodiments, the present disclosure providemethods comprising introducing the treatment fluid into a wellborepenetrating at least a portion of a subterranean formation at or above apressure sufficient to create or enhance one or more fractures in thesubterranean formation.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods and compositions of the present disclosure may providesurfactants for use in subterranean formations that are safer, lesstoxic, and/or more effective than certain other surfactants used insubterranean operations. Ethoxylated amine surfactants may be non-toxicand may be more stable as they are less sensitive to temperature, pH,and salinity variations than conventional surfactants. Another advantagemay be a synergistic effect of an ethoxylated amine surfactant withother surfactants (e.g., other ethoxylated surfactants, alkylpolyglycoside surfactants) or solvents in the fluid, which may result inlower interfacial tension than the surfactants may achieve independentlyor without the solvents. In addition to surfactant functionality,ethoxylated amines may also serve as a corrosion inhibitor.

As used herein, the term “ethoxylated amine surfactant” refers tosurfactants comprising an ethoxylated amine or derivative thereof.Ethoxylated amines are amines comprising ethylene oxide. Examples ofethoxylated amines that may be suitable for certain embodiments of thepresent disclosure include, but are not limited to compounds having thefollowing general chemical structure:

where R represents an alkyl group, and x and y are non-zero integers. Incertain embodiments, R may comprise a substituted, unsubstituted,linear, branched, cyclic, or acyclic alkyl group from C1 to C20.Variables x and y may be the same or different and may be an integerfrom 1 to 25. For example, in some embodiments, R is an alkyl group fromC10-C18 and the sum of x and y is 2-50. In certain embodiments, the sumof x and y is 2-20. In some embodiments, the ethoxylated amine is atertiary amine having one alkyl group and two or more polyoxyethylenegroups attached to the nitrogen atom. In some embodiments, the methodsand compositions of the present disclosure may comprise an ethoxylatedamine derivative.

In certain embodiments, an ethoxylated amine surfactant may be presentin a treatment fluid of the present disclosure in an amount from about1×10⁻⁵ gallons per thousand gallons of treatment fluid (gpt) up to about50 gpt. In some embodiments, the ethoxylated amine surfactant may bepresent in a treatment fluid of the present disclosure in an amount fromabout 0.1 gpt up to about 50 gpt. In some embodiments, the ethoxylatedamine surfactant may be present in a treatment fluid of the presentdisclosure in an amount from about 0.1 gpt up to about 10 gpt.

In certain embodiments, additional surfactants may be used together withthe ethoxylated amine surfactant. In some embodiments, the ethoxylatedamine surfactant may have a synergistic effect with the additionalsurfactants. For example, in some embodiments, the ethoxylated amine mayhelp disperse the additional surfactants in the fluid. Examples ofsuitable additional surfactants include, but are not limited to alkylpolyglycosides, alkoxylated alkyl alcohols and salts thereof,alkoxylated alkyl phenols and salts thereof, alkyl sulfonates, arylsulfonates, sulfates, phosphates, carboxylates, polyoxyalkyl glycols,fatty alcohols, polyoxyethylene glycol sorbitan alkyl esters, sorbitanalkyl esters, polysorbates, glucosides, quaternary amine compounds,amine oxide surfactants, and any combination thereof.

In certain embodiments, a solvent may be used together with theethoxylated amine surfactant. In some embodiments, the ethoxylated aminesurfactant may have a synergistic effect with the solvent. In certainembodiments, a treatment fluid of the present disclosure may comprise anaqueous base fluid and a solvent. In some embodiments, this may resultin lower interfacial tension than the ethoxylated amine surfactant orsolvent may achieve independently. In certain embodiments, the solventmay comprise any suitable solvent or combination thereof. Examples ofsolvents suitable for some embodiments of the present disclosureinclude, but are not limited to a non-aqueous solvent, a non-aromaticsolvent, an alcohol, glycerol, carbon dioxide, isopropanol, or anycombination or derivative thereof. Examples of non-aromatic solventsthat may be suitable for use in certain embodiments of the presentdisclosure include, but are not limited to, an ethoxylated alcohol, analkoxylated alcohol, a glycol ether, a disubstituted amide, RHODIASOLV®MSOL (a mixture of glycerine and acetone available from Solvay inHouston, Tex.), MUSOL® (isopropylidene glycerol, available fromHalliburton in Houston, Tex.), triethanolamine,ethylenediaminetetraacetic acid, N,N-dimethyl 9-decenamide, soya methylester, canola methyl ester, STEPOSOL® C-42 (a mixture of methyl laurateand methyl myristate, available from Stepan in Northfield, Ill.),STEPOSOL® SC (a mixture of methyl soyate and ethyl lactate, availablefrom Stepan in Northfield, Ill.), any combination, and any derivativethereof.

In certain embodiments, the surfactants of the present disclosure,either alone or in conjunction with other additives, may increaseproduction of hydrocarbon fluids from unconventional hydrocarbonformations. Examples of unconventional reservoirs include, but are notlimited to reservoirs such as tight sands, shale gas, shale oil, coalbedmethane, tight carbonate, and gas hydrate reservoirs. Surfactants mayaffect many variables in subterranean treatments and operations, such asinterfacial/surface tension, wettability, compatibility with otheradditives (such as other additives used in acidizing treatments), andemulsification tendency.

Without limiting the disclosure to any particular theory or mechanism,it is believed that surfactants of the present disclosure generate ashort-lived oil-in-water emulsion, aiding oil solubilization andmobilization.

In some embodiments, the surfactants of the present disclosure may actas a flowback aid. Flowback aids may reduce capillary pressure, oilblocks, and/or water blocks, improving the kinetics of flowback andminimizing the amount of fracturing fluid left behind in the formation.In addition, flowback aids may aid in the “clean up” of a proppant pack,and/or accelerate the flow of hydrocarbons through the formation and aproppant pack.

As used herein, a “water block” generally refers to a condition causedby an increase in water saturation in the near-wellbore area. A waterblock may form when the near-wellbore area is exposed to a relativelyhigh volume of filtrate from the drilling fluid. In some embodiments,increased presence of water may cause clay present in the formation toswell and reduce permeability and/or the water may collect in porethroats, resulting in a decreased permeability due to increasedcapillary pressure and cohesive forces.

As used herein, an “oil block” generally refers to a condition in whichan increased amount of oil saturates the area near the wellbore. Due tothe wettability of the subterranean formation and the resultingcapillary pressure, oil may reduce the permeability of the subterraneanformation to the flow of fluids, including oil and water. Withoutlimiting the disclosure to any particular theory or mechanism, it isbelieved that the compositions and methods described herein may remove awater or oil block by removing at least a portion of the water and/oroil in the near wellbore area and/or altering the wettability of thesubterranean formation. For example, in certain embodiments, theformation surface may be oil wet. By altering the wettability of thesurface of a subterranean formation to be more water wet, the surface ofthe formation may be more compatible with injection water and otherwater-based fluids. In certain embodiments, the methods and compositionsof the present disclosure may also reduce interfacial tension betweenthe fluid in the formation and the surfaces of the formation.

In some embodiments, the methods and compositions of the presentdisclosure may directly or indirectly reduce capillary pressure in theporosity of the formation. Reduced capillary pressure may lead toincreased water and/or oil drainage rates. In some embodiments, improvedwater-drainage rates may allow a reduction in existing water blocks, aswell as a reduction in the formation of water blocks. In certainembodiments, the methods and compositions of the present disclosure mayallow for enhanced water, oil, and/or other fluid recovery.

In certain embodiments, the ethoxylated amines of the present disclosuremay also serve as a corrosion inhibitor. For example, the methods of thepresent disclosure may inhibit corrosion in a wellbore. In someembodiments, the ethoxylated amines may prevent corrosion during theperiod of flow back and initial production.

In some embodiments, the methods and compositions of the presentdisclosure may provide treatment fluids comprising surfactants that aremore stable to variations in temperature, pH, and salinity thanconventional surfactant compositions. For example, in some embodiments,the ethoxylated amine or ethoxylated amine derivative surfactant mayprovide stable interfacial tension across a variety of temperatures, pHlevels, and salinities.

In certain embodiments of the present disclosure, ethoxylated aminesurfactants, treatment fluids, or related additives of the presentdisclosure may be introduced into a subterranean formation, a wellborepenetrating a subterranean formation, tubing (e.g., pipeline), and/or acontainer using any method or equipment known in the art. Introductionof the ethoxylated amines, treatment fluids, or related additives of thepresent disclosure may in such embodiments include delivery via any of atube, umbilical, pump, gravity, and combinations thereof. Additives,treatment fluids, or related compounds of the present disclosure may, invarious embodiments, be delivered downhole (e.g., into the wellbore) orinto top-side flowlines/pipelines or surface treating equipment.

The compositions used in the methods and compositions of the presentdisclosure may comprise any aqueous base fluid known in the art. Theterm “base fluid” refers to the major component of the fluid (as opposedto components dissolved and/or suspended therein), and does not indicateany particular condition or property of that fluids such as its mass,amount, pH, etc. Aqueous fluids that may be suitable for use in themethods and compositions of the present disclosure may comprise waterfrom any source. Such aqueous fluids may comprise fresh water, saltwater (e.g., water containing one or more salts dissolved therein),brine (e.g., saturated salt water), seawater, or any combinationthereof. In most embodiments of the present disclosure, the aqueousfluids comprise one or more ionic species, such as those formed by saltsdissolved in water. For example, seawater and/or produced water maycomprise a variety of divalent cationic species dissolved therein. Incertain embodiments, the density of the aqueous fluid can be adjusted,among other purposes, to provide additional particulate transport andsuspension in the compositions of the present disclosure. In certainembodiments, the pH of the aqueous fluid may be adjusted (e.g., by abuffer or other pH adjusting agent) to a specific level, which maydepend on, among other factors, the types of viscosifying agents, acids,and other additives included in the fluid. One of ordinary skill in theart, with the benefit of this disclosure, will recognize when suchdensity and/or pH adjustments are appropriate.

In certain embodiments, the methods and compositions of the presentdisclosure optionally may comprise any number of additional additives.Examples of such additional additives include, but are not limited to,salts, additional surfactants, acids, proppant particulates, divertingagents, fluid loss control additives, gas, nitrogen, carbon dioxide,surface modifying agents, tackifying agents, foamers, additionalcorrosion inhibitors, scale inhibitors, catalysts, clay control agents,biocides, friction reducers, antifoam agents, bridging agents,flocculants, H₂S scavengers, CO₂ scavengers, oxygen scavengers,lubricants, viscosifiers, breakers, weighting agents, relativepermeability modifiers, resins, wetting agents, coating enhancementagents, filter cake removal agents, antifreeze agents (e.g., ethyleneglycol), and the like. A person skilled in the art, with the benefit ofthis disclosure, will recognize the types of additives that may beincluded in the fluids of the present disclosure for a particularapplication.

The ethoxylated amine surfactants and compositions of the presentdisclosure can be used in a variety of applications. These includedownhole applications (e.g., drilling, fracturing, completions, oilproduction), use in conduits, containers, and/or other portions ofrefining applications, gas separation towers/applications, pipelinetreatments, water disposal and/or treatments, and sewage disposal and/ortreatments.

In some embodiments, the present disclosure provides methods for usingthe additives, treatment fluids, and related compounds to carry out avariety of subterranean treatments, including but not limited tohydraulic fracturing treatments, acidizing treatments, and drillingoperations. In some embodiments, the compounds of the present disclosuremay be used in treating a portion of a subterranean formation, forexample, in acidizing treatments such as matrix acidizing or fractureacidizing. In certain embodiments, a treatment fluid may be introducedinto a subterranean formation. In some embodiments, the treatment fluidmay be introduced into a wellbore that penetrates a subterraneanformation. In some embodiments, the treatment fluid may be introduced ata pressure sufficient to create or enhance one or more fractures withinthe subterranean formation (e.g., hydraulic fracturing).

Treatment fluids can be used in a variety of subterranean treatmentoperations. As used herein, the terms “treat,” “treatment,” “treating,”and grammatical equivalents thereof refer to any subterranean operationthat uses a fluid in conjunction with achieving a desired functionand/or for a desired purpose. Use of these terms does not imply anyparticular action by the treatment fluid. Illustrative treatmentoperations can include, for example, fracturing operations, gravelpacking operations, acidizing operations, scale dissolution and removal,consolidation operations, and the like.

Certain embodiments of the methods and compositions disclosed herein maydirectly or indirectly affect one or more components or pieces ofequipment associated with the preparation, delivery, recapture,recycling, reuse, and/or disposal of the disclosed compositions. Forexample, and with reference to FIG. 1, the disclosed methods andcompositions may directly or indirectly affect one or more components orpieces of equipment associated with an exemplary fracturing system 10,according to one or more embodiments. In certain instances, the system10 includes a fracturing fluid producing apparatus 20, a fluid source30, a proppant source 40, and a pump and blender system 50 and residesat the surface at a well site where a well 60 is located. In certaininstances, the fracturing fluid producing apparatus 20 combines a gelpre-cursor with fluid (e.g., liquid or substantially liquid) from fluidsource 30, to produce a hydrated fracturing fluid that is used tofracture the formation. The hydrated fracturing fluid can be a fluidready for use in a fracture stimulation treatment of the well 60 or aconcentrate to which additional fluid is added prior to use in afracture stimulation of the well 60. In some embodiments, the fracturingfluid producing apparatus 20 can be omitted and the fracturing fluidsourced directly from the fluid source 30. In certain embodiments, thefracturing fluid may comprise water, a hydrocarbon fluid, a polymer gel,foam, air, wet gases and/or other fluids.

The proppant source 40 can include a proppant for combination with thefracturing fluid. In certain embodiments, one or more treatmentparticulates of the present disclosure may be provided in the proppantsource 40 and thereby combined with the fracturing fluid with theproppant. The system may also include additive source 70 that providesone or more additives (e.g., ethoxylated amine surfactants, gellingagents, weighting agents, and/or other additives) to alter theproperties of the fracturing fluid. For example, the other additives 70can be included to reduce pumping friction, to reduce or eliminate thefluid's reaction to the geological formation in which the well isformed, to operate as surfactants, inhibit corrosion, and/or to serveother functions. In certain embodiments, the other additives 70 mayinclude an ethoxylated amine surfactant of the present disclosure.

The pump and blender system 50 receives the fracturing fluid andcombines it with other components, including proppant from the proppantsource 40 and/or additional fluid from the additives 70. The resultingmixture may be pumped down the well 60 under a pressure sufficient tocreate or enhance one or more fractures in a subterranean zone, forexample, to stimulate production of fluids from the zone. Notably, incertain instances, the fracturing fluid producing apparatus 20, fluidsource 30, and/or proppant source 40 may be equipped with one or moremetering devices (not shown) to control the flow of fluids, proppantparticles, and/or other compositions to the pumping and blender system50. Such metering devices may permit the pumping and blender system 50to source from one, some or all of the different sources at a giventime, and may facilitate the preparation of fracturing fluids inaccordance with the present disclosure using continuous mixing or“on-the-fly” methods. Thus, for example, the pumping and blender system50 can provide just fracturing fluid into the well at some times, justproppant particles at other times, and combinations of those componentsat yet other times.

FIG. 2 shows the well 60 during a fracturing operation in a portion of asubterranean formation of interest 102 surrounding a wellbore 104. Thewellbore 104 extends from the surface 106, and the fracturing fluid 108is applied to a portion of the subterranean formation 102 surroundingthe horizontal portion of the wellbore. Although shown as verticaldeviating to horizontal, the wellbore 104 may include horizontal,vertical, slant, curved, and other types of wellbore geometries andorientations, and the fracturing treatment may be applied to asubterranean zone surrounding any portion of the wellbore. The wellbore104 can include a casing 110 that is cemented or otherwise secured tothe wellbore wall. The wellbore 104 can be uncased or include uncasedsections. Perforations can be formed in the casing 110 to allowfracturing fluids and/or other materials to flow into the subterraneanformation 102. In cased wells, perforations can be formed using shapecharges, a perforating gun, hydro-jetting and/or other tools.

The well is shown with a work string 112 depending from the surface 106into the wellbore 104. The pump and blender system 50 is coupled a workstring 112 to pump the fracturing fluid 108 into the wellbore 104. Theworking string 112 may include coiled tubing, jointed pipe, and/or otherstructures that allow fluid to flow into the wellbore 104. The workingstring 112 can include flow control devices, bypass valves, ports, andor other tools or well devices that control a flow of fluid from theinterior of the working string 112 into the subterranean zone 102. Forexample, the working string 112 may include ports adjacent the wellborewall to communicate the fracturing fluid 108 directly into thesubterranean formation 102, and/or the working string 112 may includeports that are spaced apart from the wellbore wall to communicate thefracturing fluid 108 into an annulus in the wellbore between the workingstring 112 and the wellbore wall.

The working string 112 and/or the wellbore 104 may include one or moresets of packers 114 that seal the annulus between the working string 112and wellbore 104 to define an interval of the wellbore 104 into whichthe fracturing fluid 108 will be pumped. FIG. 2 shows two packers 114,one defining an uphole boundary of the interval and one defining thedownhole end of the interval. When the fracturing fluid 108 isintroduced into wellbore 104 (e.g., in FIG. 2, the area of the wellbore104 between packers 114) at a sufficient hydraulic pressure, one or morefractures 116 may be created in the subterranean zone 102. The proppantparticulates (and/or treatment particulates of the present disclosure)in the fracturing fluid 108 may enter the fractures 116 where they mayremain after the fracturing fluid flows out of the wellbore. Theseproppant particulates may “prop” fractures 116 such that fluids may flowmore freely through the fractures 116.

While not specifically illustrated herein, the disclosed methods andcompositions may also directly or indirectly affect any transport ordelivery equipment used to convey the compositions to the fracturingsystem 10 such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to fluidically move thecompositions from one location to another, any pumps, compressors, ormotors used to drive the compositions into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the compositions,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of preferred embodiments aregiven. The following examples are not the only examples that could begiven according to the present disclosure and are not intended to limitthe scope of the disclosure or claims.

EXAMPLES Example 1

In this example, the thermal stability of an ethoxylated amineformulation was compared to a field standard non-emulsifying surfactantformulation. Thermal stability was tested by measuring the interfacialtensions of each composition at three different conditions: (1) at roomtemperature, (2) after heating and maintaining the composition at 320°F. and 300 psi for 1 day, and (3) after heating and maintaining thecomposition at 320° F. and 300 psi for 4 days. Interfacial tensionmeasurements were obtained using a “Tracker H” Teclis Instrumentsautomated drop tensiometer. FIGS. 3A and 3B show the interfacial tensionmeasurements for each formulation at each condition. Table 1 shows thefinal interfacial tension for each formulation at each condition. Asshown in FIGS. 3A and 3B and Table 1, the ethoxylated amine formulationwas more stable to temperature variation than the field standardnon-emulsifying surfactant formulation.

TABLE 1 Interfacial Tension (mN/m) Surfactant Room 1 day at 320° F. 4days at 320° F. Formulation Temperature & 300 psi & 300 psi FieldStandard Non- 25.5 33.0 30.0 Emulsifying Surfactant FormulationEthoxylated Amine 27.9 28.9 30.2 Surfactant Formulation

Example 2

In this example, an emulsion tendency test was performed to compare theemulsion tendency of an ethoxylated amine surfactant formulation in a10% broken gel to a field standard non-emulsifying surfactantformulation in a 10% broken gel. The formulations were mixed with twodifferent crude oils and observed at room temperature to determine howlong after mixing the emulsion broke. The results of the emulsiontendency test are shown in Table 2. As shown in Table 2, the emulsionbreak time for the ethoxylated amine surfactant formulation wascomparable to the field standard non-emulsifying surfactant formulation.

TABLE 2 Emulsion Break Time (min) Surfactant Formulation Crude Oil 1Crude Oil 2 Field Standard Non- 1 2.5 Emulsifying Surfactant FormulationEthoxylated Amine 3 1 Surfactant Formulation

Example 3

In this example, pH and salinity stability was measured for anethoxylated amine formulation. Ethoxylated amine formulations comprisingvarying concentrations of NaCl (1 percent, 3 percent, and 6 percent)were prepared at three different pH levels (4, 7, and 10), and surfacetension was measured for each. The results of the surface tensionmeasurements are shown in FIG. 4, which shows that surface tension ofthe ethoxylated amine formulation was stable with respect to pH andsalinity variations.

An embodiment of the present disclosure is a method comprising:providing a treatment fluid comprising: an aqueous base fluid; and asurfactant comprising an ethoxylated amine or derivative thereof;introducing the treatment fluid into a wellbore penetrating at least aportion of a subterranean formation; and producing fluids from thewellbore during or subsequent to introducing the treatment fluid intothe wellbore.

Another embodiment of the present disclosure is a method comprisingproviding a treatment fluid comprising: an aqueous base fluid; and asurfactant comprising an ethoxylated amine or derivative thereof; andintroducing the treatment fluid into a wellbore penetrating at least aportion of a subterranean formation at or above a pressure sufficient tocreate or enhance one or more fractures in the subterranean formation.

Another embodiment of the present disclosure is a method comprisingproviding a treatment fluid comprising: an aqueous base fluid; and asurfactant comprising an ethoxylated amine or derivative thereof;introducing the treatment fluid into a wellbore penetrating at least aportion of a subterranean formation comprising an unconventionalreservoir; and producing fluids from the wellbore during or subsequentto introducing the treatment fluid into the wellbore, wherein the amountof fluids produced from the wellbore during or subsequent to introducingthe treatment fluid comprising the surfactant is greater than the amountof fluids that would be produced during or subsequent to introducing thesame treatment fluid without the surfactant.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a treatment fluidcomprising: an aqueous base fluid; a first surfactant comprising anethoxylated amine or derivative thereof; a second surfactant comprisingan ethoxylated alcohol or a salt of an ethoxylated alcohol; a thirdsurfactant selected from the group consisting of an alkoxylated alkylalcohol, an alkoxylated alkyl alcohol salt, an alkyl sulfonate, an arylsulfonate, a sulfate, a phosphate, a carboxylate, a polyoxyalkyl glycol,a polyoxyethylene glycol sorbitan alkyl ester, a sorbitan alkyl ester, apolysorbate, a glucoside, a quaternary amine compound, and anycombination thereof; and a solvent comprising glycerine and acetone;introducing the treatment fluid into a wellbore penetrating at least aportion of a subterranean formation; and producing fluids from thewellbore during or subsequent to introducing the treatment fluid intothe wellbore.
 2. The method of claim 1, wherein the ethoxylated amine orderivative thereof inhibits corrosion in at least a portion of thesubterranean formation.
 3. The method of claim 1, wherein the firstsurfactant is present in the treatment fluid in an amount from about1×10⁻⁵ gpt up to about 50 gpt based on the total volume of the treatmentfluid.
 4. The method of claim 1, wherein the treatment fluid furthercomprises an additional surfactant.
 5. The method of claim 1, whereinthe treatment fluid further comprises an additional solvent.
 6. Themethod of claim 5, wherein the additional solvent is selected from thegroup consisting of: a non-aqueous solvent, a non-aromatic solvent, analcohol, glycerol, carbon dioxide, isopropanol, any combination, and anyderivative thereof.
 7. The method of claim 1, wherein the subterraneanformation comprises an unconventional reservoir.
 8. The method of claim1, further comprising: allowing at least one of the surfactants toreduce capillary pressure in at least a portion of the subterraneanformation.
 9. The method of claim 1, wherein the amount of fluidsproduced from the wellbore during or subsequent to introducing thetreatment fluid comprising the surfactants is greater than the amount offluids that would be produced during or subsequent to introducing thesame treatment fluid without the surfactants.
 10. The method of claim 1,further comprising: allowing at least one of the surfactants to alter awettability of a surface of the formation.
 11. The method of claim 1,further comprising: allowing at least one of the surfactants to reduceinterfacial tension between a fluid in the formation and a surface ofthe formation.
 12. The method of claim 1, further comprising: allowingat least one of the surfactants to remove at least a portion of an oilblock, a water block, or both.
 13. A method comprising: providing atreatment fluid comprising: an aqueous base fluid; a first surfactantcomprising an ethoxylated amine or derivative thereof; a secondsurfactant comprising an ethoxylated alcohol or a salt of an ethoxylatedalcohol; a third surfactant selected from the group consisting of analkoxylated alkyl alcohol, an alkoxylated alkyl alcohol salt, an alkylsulfonate, an aryl sulfonate, a sulfate, a phosphate, a carboxylate, apolyoxyalkyl glycol, a polyoxyethylene glycol sorbitan alkyl ester, asorbitan alkyl ester, a polysorbate, a glucoside, a quaternary aminecompound, and any combination thereof; and a solvent comprisingglycerine and acetone; introducing the treatment fluid into a wellborepenetrating at least a portion of a subterranean formation at or above apressure sufficient to create or enhance one or more fractures in thesubterranean formation.
 14. The method of claim 13, further comprising:producing fluids from the wellbore.
 15. The method of claim 13, furthercomprising: allowing at least one of the surfactants to reduce capillarypressure in at least a portion of the subterranean formation.
 16. Themethod of claim 13, further comprising: allowing at least one of thesurfactants to remove at least a portion of an oil block, a water block,or both.
 17. The method of claim 13, wherein the subterranean formationcomprises an unconventional reservoir.
 18. A method comprising:providing a treatment fluid comprising: an aqueous base fluid; a firstsurfactant comprising an ethoxylated amine or derivative thereof; asecond surfactant comprising an ethoxylated alcohol or a salt of anethoxylated alcohol; a third surfactant selected from the groupconsisting of an alkoxylated alkyl alcohol, an alkoxylated alkyl alcoholsalt, an alkyl sulfonate, an aryl sulfonate, a sulfate, a phosphate, acarboxylate, a polyoxyalkyl glycol, a polyoxyethylene glycol sorbitanalkyl ester, a sorbitan alkyl ester, a polysorbate, a glucoside, aquaternary amine compound, and any combination thereof; and a solventcomprising glycerine and acetone; introducing the treatment fluid into awellbore penetrating at least a portion of a subterranean formationcomprising an unconventional reservoir; and producing fluids from thewellbore during or subsequent to introducing the treatment fluid intothe wellbore, wherein the amount of fluids produced from the wellboreduring or subsequent to introducing the treatment fluid comprising thesurfactant is greater than the amount of fluids that would be producedduring or subsequent to introducing the same treatment fluid without thesurfactant.
 19. The method of claim 18, further comprising: allowing atleast one of the surfactants to remove at least a portion of an oilblock, a water block, or both.